Flow management in existing wells during adjacent well hydraulic fracturing

ABSTRACT

A method of managing flow in a first producing well section when hydraulic fracturing a second well section includes reperforating the first producing well section to create a new set of perforations, pressurizing the formation through the new set of perforations, and pressurizing the formation through the second well section with a second amount of hydraulic fracturing liquid while the formation is still pressurized from the first producing well section.

BACKGROUND

Hydraulic fracturing is a technique for fracturing a subterranean formation with a pressurized liquid. The process involves injecting fluid under high pressure into a wellbore to fracture the rock of the subterranean formation. The liquid propagates throughout the fractures. When the liquid is removed, the fractures stay open because sand or other types of proppants suspended in the fracturing fluid remain in the formation's fractures and keep the fractures from closing. The open fractures provide greater access to natural resources such as natural gas and liquid petroleum and allow these natural resources to flow easier within the subterranean formation to the well bore for recovery.

Over time, the production rate of a producing well may slow down significantly enough to prompt a hydraulic refracture. Hydraulic refracturing is a process where a producing well bore is reperforated. In some case, reperforating may involve creating new holes, additional holes, or refracturing through existing holes. The formation may be re-pressurized with hydraulic fluids through the holes from the refracturing process. Often the hydraulic refracturing results in an increased production rate which may be closer to the initial production rates when the well first started producing, but the actual production rate achieved may vary depending on geology, volume of the remaining payload, downhole pressure, and other factors.

One method involving hydraulic refracturing is disclosed in U.S. Pat. No. 8,794,316 issued to David P. Craig, et al. In this reference, quantitative refracture diagnostic and fracture-injection/falloff models are discussed and may be used in methods for oil and gas subsurface formation evaluation techniques. More particularly, such methods may be used to select candidate wells and well candidate layers for stimulation treatments in a subterranean formation. An example of a method for selecting well candidate layers for stimulation treatments in a subterranean formation may comprise the steps of: selecting a candidate well; selecting a reservoir layer to be tested; performing a quantitative refracture-candidate diagnostic test on the reservoir layer; determining at least one reservoir property of the reservoir layer using the quantitative refracture-candidate diagnostic test; and modeling a proposed stimulation treatment using the at least one reservoir property in a reservoir simulation model so as to predict the efficacy of the proposed stimulation treatment.

Another method involving hydraulic refracturing is disclosed in U.S. Patent Publication No. 2009/0037112 issued to Mohamed Y. Soliman, et al. In this reference, methods, computer programs, and systems for evaluating and treating previously-fractured subterranean formations are discussed. An example method from this reference includes, for one or more of the one or more layers, determining whether there are one or more existing fractures in the layer. The method further includes, for one or more of the one or more existing fractures, measuring one or more parameters of the existing fracture and determining conductivity damage to the existing fracture, based, at least in part, on one or more of the one or more measured parameters of the existing fracture. The method further includes selecting one or more remediative actions for the existing fracture, based, at least in part, on the conductivity damage. Both of these references are herein incorporated by reference for all that they disclose.

SUMMARY

In one embodiment, a method of managing flow in a first producing well section when hydraulic fracturing a second well section may include reperforating the first producing well section to create a new set of perforations, pressurizing the formation through the new set of perforations, and pressurizing the formation through the second well section with a second amount of hydraulic fracturing liquid while the formation is still pressurized from the first producing well section.

The first producing well section may be a horizontal well section.

The second well section may be aligned with the first producing well section.

Pressurizing the formation through the second well section may include pressurizing the formation through the first producing well section and the second well section simultaneously.

Pressurizing the formation through the second well section may include alternating between pressurizing at least one segment of the first producing well section and pressurizing at least another segment of the second well section.

Pressurizing the formation through the second well section may include pressurizing at least one of the first producing well section and the second well section along its entire perforated length before pressurizing the other of the first producing well section or the second well section.

The second well section may be positioned close enough to the first producing well section that pressure from the second well section negatively affects a fracture network in the formation that directs hydrocarbons towards the first producing well section when the formation is not pressurized from the first producing well section.

In one embodiment, a method of managing flow in a first producing well section when hydraulic fracturing an adjacent, second well section may include closing off a first set of perforations in a first producing well section that was previously used to pressurize the formation through hydraulic fracturing where the first producing well section is adjacent to a second well section that has not been previously used to pressurize the formation, reperforating the first producing well section to create a second set of perforations in the first producing well section, pressurizing the formation through the second set of perforation in the first producing well section with first volume of hydraulic fracturing liquid, pressurizing the formation through the second well section with a second volume of hydraulic fracturing liquid while the formation is still pressurized from the first producing well section.

Pressurizing the formation through the second well section may include pressurizing the formation through the first producing well section and the second well section simultaneously.

Pressurizing the formation through the second well section may include alternating between pressurizing at least one segment of the first producing well section and pressurizing at least another segment of the second well section.

Pressurizing the formation through the second well section may include pressurizing at least one of the first producing well section and the second well section along its entire perforated length before pressurizing the other of the first producing well section or the second well section.

The first producing well section and the second well section may have a common well platform.

The first producing well section may be part of a first well platform and the second well section is part of a second well platform where the first well platform is independent of the second well platform.

Closing off the first set of perforations in the first producing well section may include sealing off the first set of perforations with an expandable liner.

Closing off the first set of perforations in the first producing well section may include directing a diverting agent into the first set of perforations.

Closing off the first set of perforations may include using a packer to isolate at least one segment of the existing well from at least a portion of the first set of perforations.

Reperforating the first producing well section of the well to create a second set of perforations in the first producing well section may include forming a new perforation cluster in the first producing well section between existing perforation clusters.

Reperforating the first producing well section of the well to create a second set of perforations in the first producing well section may include forming new perforation clusters through a liner disposed within the first producing well section.

Reperforating the first producing well section of the well to create a second set of perforations in the first producing well section may include forming new perforation clusters through a cement barrier formed within the first producing well section.

The method may include perforating the second well section prior to pressurizing the formation through the second well section.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 depicts an example of fracturing a target formation from a first producing well section and a second well section in accordance with aspects of the present disclosure.

FIG. 2 depicts an example of closing off a set a perforations in a first producing well bore in accordance with aspects of the present disclosure.

FIG. 3 depicts an example of reperforating a first producing well section in accordance with aspects of the present disclosure.

FIG. 4 depicts an example of pressurizing a subterranean formation in accordance with aspects of the present disclosure.

FIG. 5 depicts an example perforating a second well section in accordance with aspects of the present disclosure.

FIG. 6 depicts an example of pressurizing a formation with a second well section while the formation is still pressurized from a first producing well section in accordance with aspects of the present disclosure.

FIG. 7 depicts an example of producing from a first producing well section and a second well section in accordance with aspects of the present disclosure.

FIG. 8 depicts an example of pressurizing a formation from a first producing well section and a second well section simultaneously in accordance with aspects of the present disclosure.

FIG. 9 depicts an example of pressurizing a formation from a first vertical producing well and a second vertical well section in accordance with aspects of the present disclosure.

FIG. 10 depicts an example of closing off a set a perforations in a first producing well bore with an expandable liner in accordance with aspects of the present disclosure.

FIG. 11 depicts an example of closing off a set a perforations in a first producing well bore with a diverting agent in accordance with aspects of the present disclosure.

FIG. 12 depicts an example of closing off a set a perforations in a first producing well bore with an expandable packer in accordance with aspects of the present disclosure.

FIG. 13 depicts an example of a method for managing flow in a first producing well section when hydraulic fracturing a formation through an adjacent second well section in accordance with aspects of the present disclosure.

FIG. 14 depicts an example of a method for managing flow in a first producing well section when hydraulic fracturing a formation through an adjacent second well section in accordance with aspects of the present disclosure.

DETAILED DESCRIPTION

For purposes of this disclosure, the term “aligned” means parallel, substantially parallel, or forming an angle of less than 35.0 degrees. For purposes of this disclosure, the term “transverse” means perpendicular, substantially perpendicular, or forming an angle between 55.0 and 125.0 degrees. Also, for purposes of this disclosure, the term “length” means the longest dimension of an object. Also, for purposes of this disclosure, the term “width” means the dimension of an object from side to side. Often, the width of an object is transverse the object's length. For the purposes of this disclosure, the “effective fracture length” generally refers to just the portion of the fracture that corresponds having 90.0% of the cumulative gas flow rate from the formation to the well bore.

Additionally, for purposes of this disclosure, the term “production” generally refers to the phase that occurs after successful exploration during which hydrocarbons are drained from an oil or gas field. For purposes of this disclosure, the term “perforating” generally refers to creating communication tunnels created from the casing into the formation, through which oil or gas is produced. Common methods of perforating include using jet perforating guns equipped with shaped explosive charges. However, other perforating methods include bullet perforating, abrasive jetting, or high-pressure fluid jetting. For purposes of this disclosure, the term “perforating gun” generally refers to a device used to perforate oil and gas wells in preparation for production.

For purposes of this disclosure, the term “refracturing” generally refers to an operation to re-stimulate a well after an initial period of production. Conventional refracturing operations may attempt to bypass near-wellbore damage, reestablish good connectivity with the reservoir, and tap portions of the reservoir with higher pore pressure. Conventional refracturing operations may also be performed after a period of production that can alter the stresses in a reservoir due to depletion or the re-stimulation can allow the new fracture to reorient along a different azimuth. A successful refracturing operation may restore well productivity to closer to original or even possibly higher rates of production and extend the productive life of a well.

For purposes of this disclosure, the term “packer” generally refers to a device that can be run into a wellbore with a smaller initial outside diameter that then expands externally to seal the wellbore. Packers may employ flexible, elastomeric elements that expand. Common packers are the production or test packer and the inflatable packer. The expansion of the production packer may be accomplished by squeezing the elastomeric elements between two plates, forcing the sides to bulge outward. The expansion of the inflatable packer may be accomplished by pumping a fluid into a bladder. Production or test packers may be set in cased holes and inflatable packers are used in open or cased holes. They may be run on wireline, pipe or coiled tubing.

For purposes of this disclosure, the term “diverting agent” generally refers to agents used in stimulation treatments to ensure uniform injection over the area to be treated. Diverting agents, also known as chemical diverters, function by creating a temporary blocking effect that is safely cleaned up following the treatment, enabling enhanced productivity throughout the treated interval. In some cases, the agents are chemical and/or mechanical agents. Diverters can be in the form of things that dissolve (Bioballs®, Slicfrac®, etc.) or simply materials that attempt to plug off perforations (sand slugs). Bioballs® can be purchased from Fairmount Santrol through their website https://fairmountsantrol.com/industries/oil-gas-proppant-solutions/diverting-agents/. Slicfrac® can be purchased from Thrutubing Solutions located in Oklahoma City, Okla. U.S.A.

For the purposes of this disclosure, the term “horizontal well section” generally involves wellbores with a section of the well bore aligned with the rock layer containing the natural resource to be extracted. Generally, the horizontal section is a terminal section of the well bore and may be referred to as a “lateral.” In some cases, more than one horizontal lateral may be drilled from the same well site and share a common vertical section with other laterals. In other cases, each of the horizontal wells do not share the same vertical section, but are drilled at different surface locations. In some examples, a horizontal well bore may extend nearly 2,000 feet or longer. In contrast, a vertical well is generally much shorter. Horizontal drilling reduces the surface footprint as fewer wells are involved to access the same volume of rock. Generally, horizontal wells make contact with more of the rock bearing the natural resource and may have greater production rates over a longer period of time.

Hydraulic fracturing may be used to increase the production of natural resources to be extracted through a well bore, such as petroleum, water, or natural gas. In some cases, hydraulic fracturing can optimize the economic production of the well by maintaining the same productions rates at a lower cost. Hydraulic fracturing may increase the initial production, the estimated ultimate recovery from the well, or increase another aspect of the well's production. Hydraulic fracturing may also be used in making a first completion, such as in the zone of interest; recompleting a well, such making a completion in another part of the well; refracturing the well, such as when re-stimulating a primary completion or a recompletion; deepening the well, such as when drilling the well deeper and completing that portion of well with a smaller diameter; re-drilling the well, such as when drilling another well next to an existing well, another drilling or completion task, or combinations thereof.

The natural resources may be located in different types of rocks, such as sandstones, limestones, dolomite rocks, shale rock, coal beds, other types of formations, or combinations thereof. Hydraulic fracturing can be applied in rock formations below the earth's groundwater reservoir levels. At these depths, there may be insufficient permeability in the reservoir to allow natural gas and oil to flow from the rock into the wellbore at desirable returns. By fracturing the rock, the permeability of the formation increases thereby improving the production of the natural resource.

The placement of one or more fractures along the length of the borehole can be determined by different methods. One type of method includes using a perforating gun to create holes in the well bore's casing.

A hydraulic fracture may be formed by injecting a fracturing fluid into a wellbore with a high enough pressure through the well bore's perforations. This pressurized fluid increases the subterranean formation's pressure to a level where the rock fractures. As the rock cracks, fissures are created that allows the fracture fluid to permeate deeper into the rock and thereby increasing the formation pressure deeper and deeper into the formation thereby extending the cracks further. The hydraulic fluid may include a proppant (e.g. grains of sand, ceramic, or other particulate) that remain in the fractures after the hydraulic fluid has drained out of the formation and prevent the fractures from closing. The propped fracture maintains an increased permeability to allow the flow of the natural resource to the well.

Equipment that may be used in hydraulic fracturing may include a slurry blender, one or more high-pressure, high-volume fracturing pumps; monitoring units; units for storage and handling of proppant; chemical additive units; low-pressure flexible hoses; and gauges and meters for flow rate, fluid density, and treating pressure.

Any appropriate type of fracturing fluid may be used in accordance with the principles described in the present disclosure. In some examples, the fracturing fluid includes a slurry of water, proppant, and chemical additives. In some cases, the fracturing fluid may also include gels, foams, and compressed nitrogen, compressed carbon dioxide, compressed air, another type of compressed gas, hydrochloric acid, acetic acid, sodium chloride, polyacrylamide, ethylene glycol, borate salts, zirconium salts, chromium salts, antimony salts, titanium salts, other types of salts, sodium carbonates, potassium carbonates, glutaraldehyde, guar gum, citric acid, isopropanol, methanol, isopropyl alcohol, 2-butoxyethanol, and ethylene glycol, aluminum phosphate and ester oils or combinations thereof. The fracturing fluid may be between 85.0 percent to 95.0 liquid or gas, between 5.5 percent and 9.5 percent proppant, and 1.0 to 0.25 percent chemical additives.

In other examples, the fracturing fluid may be a gel, a foam, or be slickwater-based. Gels may be useful in situations where it would otherwise be difficult to keep the proppant in suspension. Slickwater, which is less viscous and has a lower friction, may allow fluid to be pumped at higher rates which allows fractures to be created farther out from the wellbore.

Any appropriate proppant may be used in accordance with the principles described in the present disclosure. In some cases, the proppant may be a granular material, such as sand or a synthetic material that prevents the fractures from closing after the target formation is pressurized. Types of proppant may include silica sand, resin-coated sand, bauxite, man-made ceramics, another type of proppant, or combinations thereof. Bauxite or ceramics may be used in situations where the formation pressure is high enough to crush natural silica sand.

Horizontal wellbores can be useful in shale formations where horizontal wellbores tend to produce more economically than with a vertical well. Shales may be fractured by the plug and perforation method in the well bore either in a cemented or uncemented well bore. A wireline tool may be lowered into the well bore at a first stage location to perforate the well bore. With the well bore perforated, the fracturing fluid is pumped into the formation. Next, another plug is set in the well to temporarily seal off the previously pressurized section of the well bore so the next section of the wellbore can be perforated and then pressurized with the hydraulic fracturing fluid. The process is repeated along the horizontal length of the wellbore. Fracturing creates pathways in the rock, allowing for hydrocarbons to flow from the rock to the wellbore for production. The low permeability in the shale reservoirs results in hydrocarbon molecules that are relatively immobile in the reservoir.

In other examples, sliding sleeves are used to sequentially fracture the formation at different locations along the length of the well bore. Once one stage has finished pressurizing the formation, the next sleeve is opened, concurrently isolating the previous stage, and the process repeats.

The number of stages used to hydraulically fracture the formation may vary from target formation to target formation. In some cases, a hydraulic fracturing method may have a single hydraulic fracturing stage to greater than thirty hydraulic fracturing stages. But, any appropriate number of fracturing stages may be used in accordance with the present disclosure.

When the subterranean formation is pressurized, the fracture is created along the path of least resistance. The fracture may radiate out from the well bore in a single direction or in multiple directions when a single well bore is hydraulically fractured at a time. The entire fracture length may stretch a substantial distance, but the proppant may not travel as far as the entire length of the fracture. Further, the entire length of the fracture may not cause the formation to separate a meaningful amount to increase the permeability of the target formation. Generally, just a sub-portion of the fracture length results in increasing contact with the formation to yield an increase in production. That portion of the fracture length that contributes to 90.0 percent of the increased flow through the target formation may be referred to as an effective fracture length and is generally under 300 feet long.

Propagation of fractures during hydraulic fracturing treatments is governed by in-situ stresses in the rock. Fractures will generally propagate in a direction perpendicular to the least principal stress. Close to the well, multiple fractures may emanate outward in multiple directions when a single well bore is hydraulically fractured at a time, but those fractures tend to converge together as the fractures progress outward away from the well bore. Fractures propagating in one direction tend to be long, but do not necessarily contact high volumes of rock.

Maximizing fracture density, sometimes called stimulated reservoir volume (SRV), can be a difficult task because rock resists being fractured in a complex pattern. Fracture behavior is governed by stresses in the earth. Rock tends to fracture in the direction of maximum principal stress.

Refracturing is conventionally associated with stimulating a well after an initial period of production. Refracturing is also conventionally desirable in situations where portions of the well are damaged, where better connectivity with the reservoir may increase productivity, to reorient the fractures in the formation to a different azimuth, or to access portions of the reservoir with higher pore pressure. In contrast, this disclosure includes a method that involves refracturing to prevent damage to the fracture network of an existing well bore when an adjacent well bore is undergoing a hydraulic fracturing operation. Under some conditions, hydraulic fracturing of a nearby well can damage the network of fractures that are directing the flow of oil, gas, or other types of resources from the formation towards the existing, producing well.

By re-pressurizing the formation with hydraulic fluid from the existing producing well, the fracture network is pressurized internally which protects their integrity from potentially damaging forces from the nearby fracturing operation at the adjacent well bore. In some cases, the pressurized formation from the first producing well bore may cause the fractures produced from the second well bore to be deflected away from the pressurized formation. In other situations, the pressurized formation and the additional pressure from the adjacent well bore may cause increased stress on the pressurized region of the formation leading to a greater fracture network.

In some cases when the formation containing the fracture network is not pressurized, the forces of the hydraulic fracturing from the second well bore sends vibrations, shear loads, compression loads, tensile loads, or other types of forces through into the formation. These forces may cause portions of the existing fracture network to collapse, reorient, misalign, or negatively affect the fracture network in a manner that adversely affects the flow of the natural resource into the existing well. However, when re-pressurizing the formation from the existing, producing well bore, the pressure from the hydraulic fluid in the formation may provide temporary structural support to the fracture network when the potentially damaging forces from the second well bore arrive at the formation. This increased pressure may exert an outward pressure of the fracture network that counters the external pressures arriving from the second well bore, thereby preserving the structural integrity of the fracture network.

In some embodiments, refracturing the existing, producing well section may include closing off at least a portion of the perforations in the well bore section that is desired to be protected before creating a new set of perforations in the existing, producing well section. Closing off at least a subset of the perforations may include using a packer to isolate the region of the well bore to be perforated from another region of the well section with the first set of perforations. Closing off at least a subset of the perforations may include using a diverting agent that at least partially plugs the first set of perforations or at least reduces the flow through the first set of perforations. In yet another example, closing off the first set of perforations may include the use of a liner that blocks off the first set of perforations. The liner may be an expandable liner or a liner that is cemented in place. In some cases, cement may be pumped down into the existing, producing well section and allowed to cure in place as a plug. This cement plug may be drilled out leaving a cement layer that blocks off the first set of perforations.

A perforating gun may be moved into the existing producing well section to perforate the section. The perforating gun may be used in embodiments where a first set of perforations have been closed off or also in embodiments where the first set of perforations have been let unaltered. However, in some situations it may be desirable to close off the perforations so that the flow of natural resources from the fracture network into the existing producing well do not adversely affect the performance of the perforating gun. The perforating gun may be activated to create a new, second set of perforations in the existing, producing well section.

With the second set of perforations in place, the hydraulic fluid may be pumped into the existing, producing well section to pressurize the formation. The pressure from the hydraulic fluid may force open new fractures to create a new fracture network. The new fracture network may be an enhancement to the existing fracture network or the new fracture network may be independent of the already existing fracture network. The hydraulic fracturing fluid pumped through the new fracture network may pressurize the formation holding the new fractures open so that when the forces from the fracturing operation at the second well section occur, the new fracture network may be maintained in an open state. While being held in the open state from the internal pressure caused during the refracturing operation, the forces from the second well section may have less of an adverse effect on the new fracture network at the existing, producing well bore.

Now referring to specific examples with the figures, FIG.1 depicts an example of a formation 100 pressurized from hydraulically refracturing from an existing, producing well bore 102. In this example, the first well bore 102 includes a first horizontal section 106 that extends horizontally from a first vertical section 108. Also, in this example, the second well bore 104 includes a second horizontal section 110 that extends horizontally from a second vertical section 112. The target formation 100 is between the first horizontal section 106 and the second horizontal section 110. A first fracture network 114 emanates from the first well bore 102, and a second fracture network 116 emanates from the second well bore 104.

The area of the formation pressurized from the refracture is represented with the dashed line 101. In this example, the second well bore is a new well bore that has not been used in production yet. In this example, the second well bore 104 is also involved with a hydraulic fracturing operation that pressurizes the surrounding formation through the injection of hydraulic fluid. The pressure from the second well bore 104 may also cause portions of the formation to crack creating a second fracture network that can direct hydrocarbons or other resources to the second well bore 104. However, in this example, the development of the second fracture network is affected by the pressurized region of the formation from the first existing well bore 102. The pressurized region may cause the second fracture network to develop in a way that avoids the pressurized region, integrates into the first fracture network without collapsing portions of the first fracture network, or develop in another way that does not negatively affect the first fracture network.

The stage lengths may be any appropriate length. In some examples, at least one of the stage lengths is less than 150 feet, less than 200 feet, less than 250 feet, less than 300 feet, less than 400 feet, or less than another appropriate distance.

In the example of FIG. 1, the first well bore section and the second well bore section are horizontal sections that are located at different heights. In this example, the first well bore section is located deeper within the earth than the second well bore section. The target formation is located between the varying heights of the first and second well bore sections. In this example, the first well bore section and the second well bore section may be located within the same strata, such as a layer of porous oil-bearing rock. In other examples, the first well bore section and the second well bore section may be located in different strata or even different types of strata.

The first well bore 102 and the second well bore 104 may be spaced apart at any appropriate distance where the pressures from the second well bore 104 may negatively affect the first fracture network of the formation if the formation around the first well bore 105 is not already pressurized when the second well bore is involved with the hydraulic fracturing operation. In some examples, the first well bore 102 is spaced at a distance of less than 800 feet from the second well bore 104. In some cases, the first well bore 102 is spaced at a distance of less than 600 feet from the second well bore 104. Further, the first well bore 102 may be spaced at a distance of less than 400 feet from the second well bore 104.

As the pressure recedes in the formation after pressurization, the proppant in the hydraulic fracturing liquid remains behind keeping the fractures open. With the fractures remaining open, the natural resources within the formation may move towards either the first well bore 102 or the second well bore 104. In some cases, the strata containing the natural resource is a shale material that contains oil within the pores of the shale. The downhole pressure may cause the oil in the pores to move towards areas lower in pressure, such as in the fractures towards the well bores 102, 104. This pressure differential may cause the oil to move from the subterranean formation into the well bores 102, 104 and move towards the surface where the oil can be collected.

In some cases, the first hydraulic fluid and the second hydraulic fluid are the same type of fluid, substantially the same type of hydraulic fluid, or different types of hydraulic fluid. Further, in some cases, the volume of the first hydraulic fluid is same as, substantially the same as, or different than the volume of the second hydraulic fluid. Additionally, the pressure induced with the first hydraulic fluid may be the same as, substantially the same as, or different than the amount of pressure induced with the second hydraulic fluid.

FIGS. 2-7 depict an example sequence of developing a formation with refracturing the first well bore and hydraulically fracturing the second well bore. This sequence of stages is one embodiment and other sequences are envisioned as encompassed in the claims.

The example of FIG. 2 depicts the first well bore 102 spaced apart from the second well bore 104 at a distance where hydraulic fracturing from the second well bore 104 may adversely affect the first fracture network from the first well bore if the region of the formation containing the first fracture network is not pressurized. In this example, the first well bore 102 is an existing well bore that was previously used to hydraulically fracture the formation, which resulted in a first fracture network. In the depicted example, the second well bore 104 has not been previously hydraulically fractured and is not in communication with a fracture network. In this example, the second well bore 104 does not have sections that have been perforated for production.

In this example, the second well bore 104 has been located close enough to the existing producing well bore 102 that the formation surrounding the first well bore 102 is to be refractured prior to fracturing the formation surrounding the second well bore 104. In this example, the perforations 200 of the first well bore 102 are being closed off. A liner 202 is positioned in the first well bore 102 to be aligned with the bore's perforations 200. An annular space 204 may exist between the inside surface 206 of the first well bore 102 and the liner 202. Cement 208 may be pumped down the first well bore 102 so that the cement 208 fills the gap between the liner 202 and the inside surface 206. The cement 208 may be allowed to cure in place. Cement 208 that may remain inside the liner 202 may be removed through milling or another process leaving the center of the first well bore accessible for other tools or for the flow of liquids such as hydraulic fracturing liquid or produced hydrocarbons.

While this example depicts that the perforations 200 of the first well bore 200 are closed off with cement 208, any appropriate mechanism for at least partially closing off the perforations 200 may be used. In some examples, the perforations are not closed off and the sequences of tasks involved with refracturing from the first well bore 102 proceeds with the original perforations open.

In this example, closing off the perforations occurs after the second well bore 104 is in place. However, in other examples, the perforations may be closed off prior to the second well bore 104 being positioned within the distance when refracturing can protect the fracture network of the first well bore 102.

In the example of FIG. 3, a perforating gun 300 is positioned within the central portion of the first well bore 102 within the liner 202. In this example, the perforating gun 300 is depicted discharging an explosive to form a new perforation cluster 302. In the depicted example, the new perforation cluster 302 is located in a region of the first well bore 102 that is between previously existing clusters 304, 306. However, in some cases, the new perforation cluster 302 may be created at the same site as a previously existing perforation cluster.

The new perforation cluster 302 may extend through the liner 202, the cement 208, and the surface of the first well bore 206 so that the formation 100 is in communication with the center of the first well bore 102. As a result, hydraulic fracturing fluid, hydrocarbons, other types of gases, other types of liquids, or combinations thereof may pass between the center of the first well bore 102 and the formation 100.

In the depicted example, re-perforating of the first well bore 102 may occur after the second well bore 104 is positioned within the formation 100. Or, in other examples, re-perforating the first well bore may occur before the second well bore 104 is positioned within the formation 100.

FIG. 4 depicts an example of pressurizing the formation 100 with hydraulic fracturing fluid from the first well bore 102. In this example, the hydraulic fracturing fluid is pumped through the first well bore 102, through the perforation cluster 302, and into the formation under pressure. The pressure of the hydraulic fracturing fluid going into the formation 100 may be sufficient to make cracks and fissures through the formation to create a fracture network 114 that is held open for a time due to the pressure from the hydraulic fracturing fluid. For example, while the hydraulic fracturing fluid is being pumped into the formation 100, the fracture network is held open. After discontinuing the pumping of the hydraulic fracturing fluid, hydraulic fracturing fluid can travel back into the first well bore 102 through the perforation cluster 302 and back up to the surface. However, the formation is still pressurized with the hydraulic fracturing fluid for an initial period of time and the fracture network may remain open due to primarily to the pressure from the hydraulic fracturing fluid remaining in the formation. As more of the hydraulic fracturing fluid drains out of the formation, the fracture network may begin to close. However, the proppant in the hydraulic fracturing fluid left behind in the fracture network may cause the fracture network to remain open after the formation is no longer pressurized by the hydraulic fracturing fluid. With the fracture network open due to the proppants and the hydraulic fracturing fluid having drained back into the first well bore and back to the surface, the hydrocarbons, gases, or other natural resources may drain into the first well bore from the formation to the surface.

In some examples, the second well bore 104 is already in position when the hydraulic fracturing fluid is being pushed through the first well bore 102 into the formation 100.

FIG. 5 depicts an example of making perforations 500 in the second well bore 104 while the formation is still pressurized with hydraulic fracturing fluid from the first well bore 102. In this example, the formation is still being actively pressurized while the hydraulic fracturing fluid is being actively pumped into the formation 100. The perforations 500 in the second well bore 104 may be formed with a perforating gun 300.

FIG. 6 depicts an example of performing a hydraulic fracturing operation from the second well bore 104 while the formation 100 is still pressurized from the hydraulic fracturing fluid from the first well bore 102. In this example, pumping the hydraulic fracturing fluid into the formation from the first well bore is discontinued while the hydraulic fracturing fluid is pumped into the formation from the second well bore 104. In this example, at least some of the hydraulic fracturing fluid is draining from the formation into the first well bore 102 while the hydraulic fracturing operation is occurring through the second well bore, but the first fracture network of the first well bore remains open primarily from the pressure from the hydraulic fracturing fluid provided through the first well bore 102.

The hydraulic fracturing fluid pumped into the formation is pumped with a pressure sufficient to create a second fracture network 116 around the second well bore 104. In this example, the second fracture network 116 is depicted as being created so as to avoid the pressurized region of the formation 100 that is pressurized from the hydraulic fracturing fluid of the first well bore. The pressurized region of the formation 100 is illustrated by being encompassed with the dashed line 101. While the example of FIG. 6 does not depict that the first fracture network 114 and the second fracture network 116 interconnect, in some examples, the first and second fracture networks may interconnect in a manner that does not significantly adversely affect the flow from the formation to the first well bore 102.

FIG. 7 depicts an example where pumping the hydraulic fracturing fluid into the formation is discontinued in both the first well bore 102 and the second well bore 104. As a result, the hydraulic fracturing fluid may drain from the formation 100 into the both the first well bore 102 and the second well bore 104. After the hydraulic fracturing fluid is drained back into the well bores 102, 104, hydrocarbons, gases, or other natural resources may drain into the well bore 102, 104. During this draining process, the first fracture network 114 may maintain enough integrity that the flow is substantially uncompromised from the pressure imposed on the formation 100 when the second fracture network 116 was formed.

FIG. 8 depicts an example where the formation 100 is being pressurized with hydraulic fracturing fluid from both the first well bore 102 and the second well bore 104 at the same time. In this example, the first and second fracture networks 114, 116 may be developed at least in part at the same time. In some examples, pressurizing the formation 100 from both well bores 102, 104 at the same time may create a higher pressure that increases the effective surface areas of either or both of the first and second fracture networks 114, 116.

In some examples, simultaneously creating fractures from the first well and the second well may include triggering the hydraulic fracturing events in both wells at exactly the same time. In some cases, simultaneously creating fractures from the first well and the second well may include triggering the hydraulic fracturing events in both wells within one minute of each other, within five minutes of each other, within ten minutes of each other, within 15 minutes of each other, within 25 minutes of each other, within another appropriate time period, or combinations thereof.

In other examples, simultaneously creating fractures from the first well and the second well include different triggering start time, but that at least some period of time exists where the pressure from the first well and the pressure from the second well are increasing at the same time. For example, in some cases, pressurizing a target formation from a first well from a base formation pressure to a peak formation pressure may occur over a period of time. This period of time may be referred to as a first pressurization time period. Likewise, pressurizing the target formation from the second well from the base formation pressure to the peak formation pressure may also occur over a period of time. This second period of time may be referred to as a second pressurization time period. Thus, for the purposes of this disclosure, simultaneously creating fractures in the target formation from the first well and creating fractures in the target formation from the second well may include having at least some temporal overlap between the first pressurization time period and the second pressurization time period.

In another example, simultaneously creating fractures from the first well and the second well include having at least some period of time that exists where the pressure from the first well and the pressure from the second well are increased at the same time. In this example, the target formation remains in an increased pressurized state even after reaching a peak pressure. After reaching the peak pressure, the pressure in the target formation may diminish, but still have an elevated pressure above the base formation pressure resulting the hydraulic fluid from either the first well or the second well. Fractures may be created even after the formation pressure is diminishing. After some point, the formation pressure may return to the base formation pressure or drop below the base formation pressure. The time period in which the target formation initially increases pressure from the base formation pressure and returns to at least 50 percent of the base pressure from the hydraulic fluid from the first well may be referred to as the first elevated pressure time period. Similarly, the time period in which the target formation initially increases pressure from the base formation pressure and returns to at least 50 percent of the base pressure from the hydraulic fluid from the second well may be referred to as the second elevated pressure time period. In some examples, simultaneously creating fractures from the first well and the second well may include having a temporal overlap between the first elevated pressure time period and the second elevated pressure time period.

In another example, simultaneously creating fractures from a first well and a second well may refer to a time period in which fractures are still forming in the target formation as a result of the hydraulic fracturing. In some cases, as the target formation is pressurized, the stresses in the target formation cause the formation to move creating the fractures, but as the formation depressurizes the target formation may still move resulting in additional fractures.

FIG. 9 depicts an example of a first well bore 900 and a second well bore 900 that are vertically oriented. In these examples, the first well bore 900 may be an existing well bore that is refractured in a similar manner as described in conjunction with FIGS. 2-8 and the second well bore 902 may be a well bore that has not previously been perforated for production as described in relation to the preceding description. The principles described above relating to the horizontal wells may be applied to vertical wells.

FIG. 10 depicts an example of closing off perforations 1000 in the existing production well 1002. In this example, a liner 1004 is inserted into the annulus 1006 of the existing well adjacent to the perforations 1000. A mandrel 1008 is used to expand the liner 1004 to close of the perforations 1000. In other examples, an inflatable packer may be used to expand the liner.

FIG. 11 depicts an example of closing off perforations 1000 in the existing production well 1002. In this example, a diverting agent 1100 is used to at least partially block off the perforations 1000. In some cases, the diverting agent 1100 entirely closes off the perforations 1000.

FIG. 12 depicts an example of closing off perforations 1000 in the existing production well 1002. In this example, a packer 1201, such as an inflatable packer, is used to close off a section 1200 of the existing production well 1002 that contains the perforations 1000. In this example, new perforations 1202 may be created in the unclosed off section 1204. The hydraulic fracturing fluid may be pumped through the new perforations to create a new fracture network without traveling into the closed off section 1200.

FIG. 13 shows a flowchart illustrating a method 1300 of managing flow in existing wells during adjacent well hydraulic fracturing. The operations of method 1300 may be implemented by any of the systems described in FIGS. 1-12 or their components as described herein. In this example, the method 1300 includes reperforating 1302 a first producing well section to create a new set of perforations, 1304 pressurizing a formation through the new set of perforations, and 1306 pressurizing the formation through the second well section with a second amount of hydraulic fracturing liquid while the formation is still pressurized from the first producing well section.

At block 1302, the first producing well may be reperforated to create at least one new perforation that is capable of exchanging liquid or gas between the formation and the inside of the first producing well. In some examples, multiple new clusters of perforations are formed. Further, any appropriate type of method for creating a new cluster of perforations may be used in accordance with the principles described herein.

At block 1304, hydraulic fracturing fluid can be directed into the formation through the perforations in the first existing well. In some examples, the pressure from this first amount of hydraulic fracturing fluid may create or at least create a fracture network emanating from the first well open for at least a period of time that the formation is pressurized. After the formation has depressurized, the fracture network may remain open due to the proppants from the hydraulic fracture network. In some cases, the fracture network is open as much or more than when the formation is depressurized and kept open due to the proppant.

At block 1306, the formation may be pressured through the second well bore. In some cases, this pressurization from the second well bore is the first time that the second well has been used to pressurize the formation. In some cases, the second well bore is perforated and then used to pump hydraulic fracturing liquid into the formation. This second amount of hydraulic fracturing liquid may create a pressure sufficient in the formation to create a second fracture network in the formation.

In some cases, due to the pressure already in the formation where the first fracture network exists, the first fracture network may be protected from being adversely affected when the second fracture network is being formed. In some cases, the second fracture network is formed in such a way so as to avoid interacting with the first fracture network. In other examples, the second fracture network may form in such a manner that the first and second fracture networks interconnect with each other, but not in a manner that significantly impedes the flow or otherwise adversely affects the flow of the first fracture network.

FIG. 14 shows a flowchart illustrating a method 1400 of managing flow in existing wells during adjacent well hydraulic fracturing. The operations of method 1400 may be implemented by any of the systems described in FIGS. 1-12 or their components as described herein. In this example, the method 1400 includes closing 1402 off a first set of perforations in a first producing well section that was previously used to pressurize the formation through hydraulic fracturing where the first producing well section is adjacent to a second well section that has not been previously used to pressurize the formation, reperforating 1404 the first producing well section to create a second set of perforations in the first producing well section, pressurizing 1406 the formation through the second set of perforations in the first producing well section with the first volume of hydraulic fracturing liquid, and pressurizing 1408 the formation through the second well section with a second volume of hydraulic fracturing liquid while the formation is still pressurized from the first producing well section.

At block 1402, the perforations in the first well bore may be closed off. Any appropriate mechanism for closing off the perforations may be used in accordance with the principles described in this disclosure. The result of closing off the perforations is that the flow through the perforations is at least partially restricted. In some examples, the flow through a perforation is entirely blocked. In some cases, just a portion of the perforations are entirely blocked while other perforations maintain at least some flow though.

At block 1404, in this example, a second set of perforations are formed in the first well bore. The first set of perforations may be the set of perforations that were closed off The second set of perforations may be created through any appropriate mechanism based on the principles described in the present disclosure.

At block 1406, the formation is pressurized through at least the second set of perforations formed in the first well bore.

At block 1408, the formation is pressurized through the second well bore. In some cases, the second well has never been previously used to pressurize the formation and a new fracture network emanating from the second well bore is created in such a way to avoid significantly adversely affecting the fracture network emanating from the first well bore.

It should be noted that the methods described above describe possible implementations, and that the operations and the steps may be rearranged or otherwise modified and that other implementations are possible. Furthermore, aspects from two or more of the methods may be combined.

The description herein is provided to enable a person skilled in the art to make or use the disclosure. Various modifications to the disclosure will be readily apparent to those skilled in the art, and the generic principles defined herein may be applied to other variations without departing from the scope of the disclosure. Thus, the disclosure is not limited to the examples described herein, but is to be accorded the broadest scope consistent with the principles and novel features disclosed herein. 

What is claimed is:
 1. A method of managing flow in a first producing well section when hydraulic fracturing a second well section, comprising: reperforating the first producing well section to create a new set of perforations; pressurizing the formation through the new set of perforations; pressurizing the formation through the second well section with a second amount of hydraulic fracturing liquid while the formation is still pressurized from the first producing well section.
 2. The method of claim 1, wherein the first producing well section is a horizontal well section.
 3. The method of claim 1, wherein the second well section is aligned with the first producing well section.
 4. The method of claim 1, wherein pressurizing the formation through the second well section includes pressurizing the formation through the first producing well section and the second well section simultaneously.
 5. The method of claim 1, wherein pressurizing the formation through the second well section includes alternating between pressurizing at least one segment of the first producing well section and pressurizing at least another segment of the second well section.
 6. The method of claim 1, wherein pressurizing the formation through the second well section includes pressurizing at least one of the first producing well section and the second well section along its entire perforated length before pressurizing the other of the first producing well section or the second well section.
 7. The method of claim 1, wherein the second well section is positioned close enough to the first producing well section that pressure from the second well section negatively affects a fracture network in the formation that directs hydrocarbons towards the first producing well section when the formation is not pressurized from the first producing well section.
 8. A method of managing flow in a first producing well section when hydraulic fracturing an adjacent, second well section, comprising: closing off a first set of perforations in a first producing well section that was previously used to pressurize the formation through hydraulic fracturing where the first producing well section is adjacent to a second well section that has not been previously used to pressurize the formation; reperforating the first producing well section to create a second set of perforations in the first producing well section; pressurizing the formation through the second set of perforation in the first producing well section with first volume of hydraulic fracturing liquid; pressurizing the formation through the second well section with a second volume of hydraulic fracturing liquid while the formation is still pressurized from the first producing well section.
 9. The method of claim 8, wherein pressurizing the formation through the second well section includes pressurizing the formation through the first producing well section and the second well section simultaneously.
 10. The method of claim 8, wherein pressurizing the formation through the second well section includes alternating between pressurizing at least one segment of the first producing well section and pressurizing at least another segment of the second well section.
 11. The method of claim 8, wherein pressurizing the formation through the second well section includes pressurizing at least one of the first producing well section and the second well section along its entire perforated length before pressurizing the other of the first producing well section or the second well section.
 12. The method of claim 8, wherein the first producing well section and the second well section have a common well platform.
 13. The method of claim 8, wherein the first producing well section is part of a first well platform and the second well section is part of a second well platform, where the first well platform is independent of the second well platform.
 14. The method of claim 8, wherein closing off the first set of perforations in the first producing well section includes sealing off the first set of perforations with an expandable liner.
 15. The method of claim 8, wherein closing off the first set of perforations in the first producing well section includes directing a diverting agent into the first set of perforations.
 16. The method of claim 8, wherein closing off the first set of perforations includes using a packer to isolate at least one segment of the existing well from at least a portion of the first set of perforations.
 17. The method of claim 8, wherein reperforating the first producing well section of the well to create a second set of perforations in the first producing well section includes forming a new perforation cluster in the first producing well section between existing perforation clusters.
 18. The method of claim 8, wherein reperforating the first producing well section of the well to create a second set of perforations in the first producing well section includes forming new perforation clusters through a liner disposed within the first producing well section.
 19. The method of claim 8, wherein reperforating the first producing well section of the well to create a second set of perforations in the first producing well section includes forming new perforation clusters through a cement barrier formed within the first producing well section.
 20. The method of claim 8, further including perforating the second well section prior to pressurizing the formation through the second well section. 